System and method for intermittent gas lift

ABSTRACT

A gas-lift apparatus and method for use in a well in which liquids accumulate in a liquid zone. The apparatus comprises a first string extending into the liquid zone and having upper and lower ends; a second string surrounding the first string and defining an annulus therewith, the second string extending a distance from the first string lower end such that the annulus has upper and lower ends, the annulus being closed at its upper and lower ends and defining a chamber, the chamber being in fluid communication with the inside of the first string; a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus; a gas valve allowing the flow of gas from the first string into the upper end of the chamber; and a valve for controlling the flow of gas into the upper end of said inner string.

RELATED CASES

The present application claims benefit of U.S. Application Ser. No. 61/221,169, filed on 29 Jun. 2009, which is incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to a system and apparatus for removing water from a deep gas well.

BACKGROUND OF THE INVENTION

Hydrocarbon gas from subsurface earth formations is initially produced by the inherent formation pressure of the gas in the formation. Over time, however, water vapor in the gas stream condenses on the way to surface. As production rates decline, the velocity is no longer able to lift fluids to the surface. Water droplets coalesce, run down tubulars, and collect at the bottom of the wellbore. Eventually, the fluid level rises above the level of the well perforations. This increases bottom hole flowing pressure and restricts production. When this occurs, it is advantageous to remove the liquids from the well in order to increase the gas flow rate.

Possible solutions to this problem include velocity strings, capillary string injecting foamers, and pumps to continuously or intermittently pump the water to the surface to remove the hydrostatic barrier that the water creates.

A common practice is to use a plunger to intermittently lift the liquids. Referring briefly to FIGS. 1-2, in conventional techniques a system 10 is used that comprises a wellbore 12, gas lift tubing string 14, and an inner tubing string 16. Wellbore 12 may be cased. It will be understood that the Figures are not drawn to scale and that the total depth of the well may be several thousand feet.

An annulus 22 is defined between the wellbore or casing and gas lift tubing string 14. A gas production valve 32, gas lift inlet valve 34, and gas lift outlet valve 36 control the flow of fluids at the upper ends of annulus 22, tubing string 14, and inner string 16, respectively. At the bottom of gas lift string 14, a standing valve 38 controls the flow of fluid into tubing string 14 through an opening 28. There is fluid communication between the inside of tubing string 14 and the inside of inner string 16. One or more perforations 42 enhance the flow of fluids out of the formation and into the wellbore.

An optional slidable plunger 40 sealingly engages the inside of inner string 16. Plunger 40 is designed to allow fluids to flow up through or around the plunger and into inner string 16 until plunger 40 starts moving upward, whereupon plunger changes shape such that it forms a seal with the inside of inner string 16. For example, plunger 40 may comprise chevron type seals that allow the fluid to flow past in one direction, but tend to prevent fluid from flowing past in the other direction.

In operation, gas coming out of the formation flows up annulus 22 and out through valve 32. As it does, water enters the well from the formation and/or condenses and falls to the bottom of the well. Without significant backpressure in gas lift tubing string 14, water collecting at the bottom of the well enters gas lift tubing string 14 through opening 28.

At some point, it will be desirable to remove a portion of the collected water. This may occur when the water level rises to the level of the perforations (as shown in FIG. 1 at 44), after a predetermined period of time, or when a predetermined amount of liquid has collected. At this point, gas lift inlet valve 34 is opened, increasing the pressure inside string 14 and forcing standing valve 38 closed, as shown in FIG. 2. With standing valve 38 closed, lift gas is forced into inner string 16, advancing plunger 40 upward, along with a slug of accumulated fluids above and perhaps below it. This system will work with or without the plunger, providing there is a long enough water column.

After the plunger reaches the surface, the lift gas vents until hydrostatic pressure at the bottom of the well is sufficient to open the standing valve and the cycle repeats. While fluids enter the tubing, the plunger falls back to bottom.

One advantage of intermittent gas lift techniques is that they lift fluids without putting any backpressure on the formation. While useful in shallow wells, conventional intermittent gas lift techniques require produced gas to flow up the annulus. Flowing gas up the annulus is acceptable in shallow low pressure gas applications; however, issues such as high pressure, hydrogen sulfide, sulphur deposition, paraffin deposition, and local regulations may prohibit flow up the annulus. Thus, there remains a need for an effective technique for removing water from deep gas wells.

SUMMARY OF THE INVENTION

In accordance with preferred embodiments of the invention a system and technique are provided for removing water from deep gas wells.

In some embodiments, the system may be an intermittent gas-lift apparatus for use in a well that produces gas and liquid, in which liquids accumulate in a liquid zone in the wellbore. The system may comprise a first string extending into the liquid zone and having an upper end and a lower end, a second string surrounding the first string and defining an annulus therewith, the second string extending a predetermined axial distance from the first string lower end such that said annulus has an upper end and a lower end, the annulus being closed at its upper and lower ends so as to define a chamber, the chamber being in fluid communication with the inside of the first string, a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus, a gas valve allowing the flow of gas from the first string into the upper end of the chamber, and a valve for controlling the flow of gas into the upper end of the first string.

The first string may comprise coiled tubing and the second string may comprise production tubing. The system includes an optional plunger slidably disposed in the first string.

In other embodiments, the invention comprises a method for producing gas from a well that produces gas and liquid, in which liquids accumulate in a liquid zone in the wellbore. The method may comprise the steps of: a) providing in the well an apparatus comprising: a first string extending into the liquid zone and having an upper end and a lower end, a second string surrounding the first string and defining an annulus therewith, said second string extending a predetermined axial distance from the first string lower end, such that said annulus has an upper end and a lower end, said annulus being closed at its upper and lower ends so as to define a chamber, said chamber being in fluid communication with the inside of said first string, a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus, a gas valve allowing the flow of gas from the first string into said chamber, and a valve for controlling the flow of gas through the upper end of said inner string; b) allowing liquid to flow from the wellbore into the annulus; c) pumping gas into the annulus via the gas valve and preventing liquid from flowing out of the annulus until a desired pressure is reached; and d) allowing gas to flow out of the annulus via the inner string while preventing gas from flowing out of the annulus via the gas valve, such that the gas flowing out of the annulus propels a slug of liquid toward the surface.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed understanding of the invention, reference is made to the accompanying wherein:

FIGS. 1 and 2 are schematic illustrations of two modes of a prior art system;

FIGS. 3-5 are schematic illustrations of three modes of a system constructed in accordance with an embodiment of the invention; and

FIG. 6 is a schematic illustration of a system constructed in accordance with an alternative embodiment of the invention.

It will be understood that the Figures illustrate a system that is designed for use in a hydrocarbon production well. Positions of equipment are illustrated relative to the top of the well (the earth's surface) or the bottom of the well, but such illustration is schematic only. The Figures are not to scale and the distance between the top and bottom of the well may be several thousand feet.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Referring now to FIGS. 3-5, a system 100 according to the preferred embodiments of the present invention is positioned in a wellbore 12. The system 100 includes a production string 114 and an inner string 116. Inner string 116 preferably but not necessarily comprises coiled tubing. At the surface, a production valve 124 controls the flow of fluids out of production string 114 and a lift gas inlet valve 126 and a lift gas vent valve 128 control the fluid into and out of, respectively, inner string 116. Lift gas is preferably provided to lift gas inlet valve 126 via a high pressure lift gas feed line (not shown). A packer 115 is preferably set at the bottom of production string 114 so as to isolate the portion of the annulus above that point.

The system preferably includes a crossover 130 that is preferably located several thousand feet from the bottom of the hole. Below crossover 130, a concentric outer string 118 surrounds inner string 116, forming an annulus 117 therebetween. A gas check valve 144 is preferably disposed in the wall of inner string 116 near crossover 130. An unloading valve 146 is preferably disposed in the wall of outer string 118 near the bottom of string 118. A standing valve 129 controls the flow of fluids from the borehole into the bottom of outer string 118. One or more passageways 123 provide fluid communication between the inside of outer string 118 and the inside of inner string 116.

Referring now to FIG. 3, during production, lift gas inlet valve 126 is normally closed and vent valve 128 is open. Water flows accumulates at the bottom of the wellbore and flows into the concentric tubing through standing valve 129, and produced gas flows out through production string 114, as indicated by arrow 145.

Referring now to FIG. 4, when it is desired to lift fluids, vent valve 128 closes and lift gas inlet valve 126 opens. This allows pressurized gas to flow down through inner string 116. Standing valve 129 closes as a result of the pressure differential between the inside of outer string 118 and the wellbore and gas check valve 144 allows high pressure lift gas to pass from the coiled tubing into annulus 117. Because the system is closed, the pressure inside inner string 116 and annulus 117 will rise until it reaches line pressure, i.e. the pressure in the high pressure lift gas feed line.

Referring now to FIG. 5, once the pressure inner string 116 and annulus 117 reaches line pressure, lift gas inlet valve 126 closes. Vent valve 128 opens, allowing gas inside the coiled tubing to flow back to the surface and decreasing the pressure in inner string 116. Check valve 144 prevents the pressurized gas in annulus 117 from flowing back into inner string 116, with the result that the pressurized gas trapped in annular space 117 expands toward the bottom of the well and up through inner string 116. As the expanding gas from annulus 117 flows up through inner string 116, it pushes a slug of liquid 150 ahead of it to the surface, thereby reducing the amount of liquid in the bottom of the well. After expelling slug 150, the lift gas continues to vent through valve 128 until the pressure inside the tubing equals the vent pressure.

As liquid continues to accumulate at the bottom of the well, the hydrostatic pressure of liquid below standing valve 129 eventually becomes higher than the pressure inside concentric outer string 118, at which point standing valve 129 opens, allowing liquid to again enter concentric string 118 and the cycle repeats.

If desired, valve 146 at the bottom of the concentric string may be included and used for initial unloading of downhole liquids.

An advantage of the present invention is that produced gas is able to flow out of the formation and up though production string 114 without restriction throughout the entire lift cycle, as indicated by arrow 145. Standing valve 129 ensures that all lift gas is confined within the inner and outer tubing 116, 118. Thus, water can be removed from the well without changing the bottom hole flowing pressure. This is in contrast to conventional systems, which put additional backpressure on the formation during lift cycles or require the well to be shut in in order to build up sufficient downhole pressure to intermittently lift fluids. With the present system, the well will continue to flow at normal rates with the normal bottom hole flowing pressure.

A further advantage of the present system is that it does not require the installation of concentric tubing strings extending the full depth of the well. By contrast, the system shown in FIGS. 1 and 2 requires concentric tubing strings from the surface to the bottom of the well. For deep wells, the amount of gas required to be injected in order to perform a gas lift operation using the system of FIG. 1 would be significant. In addition, by providing a chamber that extends to less than the full depth of the well, significant equipment cost savings may be realized. Still further, the present system avoids the need for a downhole pump or similar equipment.

It is believed that the suitable pressures for application to annulus 117 during the pressurization portion of the cycle range between 400 psig and 1,400 psig, depending on the volume of water per lift, depth, and the axial length of annulus 117. The length of annulus 117 can be determined using the expected line pressure and the ratio of the annulus volume to the total tubing volume. In some embodiments, it may be desirable to design the system such that the ratio of the volume of the gas in the pressured annulus, when expanded to vent pressure, to the volume of inner string 116 is in the range of 5 to 15.

As mentioned above, the Figures are not to scale. The distance between crossover 130 and the bottom of inner string 116 is likely to be several thousand feet. By way of example only, a 10,000′ well might have a production string packer 115 at around 6,000′, crossover 130 at 6,500′, and the bottom of standing valve 129 at 9,990′, with casing perforations in stages from 7,000′ to 9,500′. Thus, the axial length of annulus 117 may, in various embodiments, be less than 75%, less than 67%, less than 50%, less than 40%, or even less than 25% of the total length of inner string 116.

Not all wells are vertical. If, for example, the well is highly deviated, liquid in the well may accumulate in a liquid zone that is not at the remote end of the wellbore. It will be understood that references to a liquid accumulation zone include any such zone, regardless of whether it is at the end of the wellbore.

In an alternative embodiment, the principles described above can be applied using a combination of a production tubing and an inner string instead of an inner string supporting an outer string on a crossover. Referring to FIG. 6, such a system preferably includes a production string 214 and packer 115 as described above. Instead of a length of coiled tubing, an inner tubing string 216 extends through the production string 214. Both inner tubing string 216 and production string 214 terminate near the bottom of the hole. An annulus 217 is defined between inner tubing string 216 and production string 214. The upper and lower ends of annulus 217 are preferably sealed by a packer 215 and a seating assembly 219, respectively.

A standing valve 229 controls the flow of fluids into the bottom of inner string 216. Fluid passageways 222 through the wall of inner string 216 allow fluids to flow between annulus 217 and the inside of inner tubing string 216. Passageways 224 through the wall of production tubing 114 allow produced gas to flow from the wellbore into annulus 217. Thus, as in the embodiment described above, valve 229 controls the flow of fluids into annulus 217.

The system illustrated in FIG. 6 functions in the same manner as the system of FIG. 3. Thus, pressurized gas is supplied to annulus 217 via inner tubing string 216 and the expansion of that gas is used to propel a slug of liquid up out of the well. An optional plunger (not shown) may be included within inner string 216 to keep lift gas from over-riding the fluid. In some embodiments, standing valve 129 and gas valve 244 can be maintained with wireline.

In yet another embodiment (not shown), an intermediate-diameter conventional tubing string may be hung from a flow-through tubing hanger disposed between the production tubing and an inner string. The inner string may comprise coiled tubing or conventional tubing. A seal is provided between the intermediate string and the inner string so that the annulus therebetween can receive and contain the pressurized gas. Once the annulus has reached line pressure, the pressure in the inner string is released, the check valve closes to prevent backflow, and the gas in the annulus expands, propelling a slug of liquid upward.

In each of the embodiments disclosed herein, it will be understood that the upper and lower ends of the inner and outer string, the annulus, and the standing valve could be configured differently, so long as a chamber is defined and liquids can flow into the chamber, gas can be pumped into the chamber, and the expanding gas can be used to propel a slug of liquid from the chamber to the surface or a predetermined outflow point. 

1. An intermittent gas-lift apparatus for use in a well that produces gas and liquid, in which liquids accumulate in a liquid zone in the wellbore, comprising: a first string extending into the liquid zone and having an upper end and a lower end; a second string surrounding the first string and defining an annulus therewith, said second string extending a predetermined axial distance from the first string lower end such that said annulus has an upper end and a lower end, said annulus being closed at its upper and lower ends so as to define a chamber, said chamber being in fluid communication with the inside of said first string; a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus; a gas valve allowing the flow of gas from the first string into the upper end of the chamber; and a valve for controlling the flow of gas into the upper end of said first string.
 2. The apparatus according to claim 1 wherein the axial length of said annulus is less than 50% of the length of said first string.
 3. The apparatus according to claim 1 wherein the first string comprises coiled tubing.
 4. The apparatus according to claim 1 wherein the second string comprises production tubing.
 5. The apparatus according to claim 1, further including a plunger slidably disposed in said first string.
 6. A method for producing gas from a well that produces gas and liquid, in which liquids accumulate in a liquid zone in the wellbore, comprising the steps of: a) providing in the well an apparatus comprising: a first string extending into the liquid zone and having an upper end and a lower end; a second string surrounding the first string and defining an annulus therewith, said second string extending a predetermined axial distance from the first string lower end such that said annulus has an upper end and a lower end, said annulus being closed at its upper and lower ends so as to define a chamber, said chamber being in fluid communication with the inside of said first string; a check valve controlling the flow of liquid into from the wellbore into the lower end of said annulus; a gas valve allowing the flow of gas from the first string into said chamber; and a valve for controlling the flow of gas through the upper end of said first string b) allowing liquid to flow from the wellbore into the annulus; c) pumping gas into the annulus via the gas valve and preventing liquid from flowing out of the annulus until a desired pressure is reached; and d) allowing gas to flow out of the annulus via the inner string while preventing gas from flowing out of the annulus via the gas valve, such that the gas flowing out of the annulus propels a slug of liquid toward the surface.
 7. The method according to claim 6 wherein the axial length of the annulus is less than 50% of the length of the first string.
 8. The method according to claim 6 wherein the first string comprises coiled tubing.
 9. The method according to claim 6 wherein the second string comprises production tubing.
 10. The method according to claim 6, wherein the first string includes a plunger slidably disposed therein. 